Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas from a subterranean formation and the extraction of geothermal heat from a subterranean formation. A wellbore may be formed in a subterranean formation using a drill bit, such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). Earth-boring rotary drill bit are rotated and advanced into a subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. Often various tools and components, including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through an annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore.
It is known in the art to use what is referred to in the art as a “reamer” device (also referred to in the art as a “hole opening device” or a “hole opener”) in conjunction with a drill bit as part of a bottom hole assembly when drilling a wellbore in a subterranean formation. In such a configuration, the drill bit operates as a “pilot” bit to form a pilot bore in the subterranean formation. As the drill bit and bottom hole assembly advance into the formation, the reamer device follows the drill bit through the pilot bore and enlarges the diameter of, or “reams,” the pilot bore.
As a wellbore is being drilled in a formation, axial force or “weight” is applied to the drill bit (and reamer device, if used) to cause the drill bit to advance into the formation as the drill bit forms the wellbore therein. This force or weight is referred to in the art as the “weight-on-bit” (WOB). When using a reamer device in conjunction with a drill bit, the weight-on-bit is distributed between the drill bit and the reamer device, as both the drill bit and the reamer device contact uncut portions of the formation or formations being drilled. Therefore, as used herein, the term “weigh-on-bit,” when used in conjunction with a drilling system or tool assembly including both a pilot bit and a reamer device, means the sum of the weight on the pilot bit and the weight on the reamer device.
A wellbore may, and typically does, extend through different formations or layers of geological material. The different formations may exhibit different physical properties. For example, some formations are relatively soft and are easily drilled through, while others are relatively hard and difficult to drill through. As a wellbore is drilled through a relatively hard formation and into an underlying softer formation using a bottom hole assembly that includes a drill bit and a reamer device longitudinally above the drill bit in the bottom hole assembly, the drill bit will quickly remove material from the softer formation while the reamer continues to more slowly ream out the wellbore in the harder formation. In such situations, the rate of penetration (ROP) of the reamer in the hard formation may be lower than the maximum potential rate of penetration at which the drill bit is capable of advancing into the lower, softer formation. As a result, the rate of penetration of the bottom hole assembly is limited by the rate of penetration of the reamer device, and the drill bit may begin to drill out the underlying, softer formation material without advancing into the formation at a rate sufficient to maintain a consistent, desired depth of cut (DOC) by the cutting structures of the drill bit. Consequently, the weight-on-bit applied to the bottom hole assembly may become undesirably unevenly distributed or proportioned between the reamer and the drill bit such that all or at least a majority of the weight-on-bit is applied to the reamer device and the portion of the bottom hole assembly distal to the reamer device rotates without sufficient weight-on-bit. Undesirable, and potentially damaging, vibrations in the bottom hole assembly and/or drill string may occur as a result of such an undesirable distribution of the weight-on-bit between the reamer and the drill bit.